The exemplary embodiments described herein relate to methods for analyzing sag in a section of a wellbore via computational methods and performing wellbore operations based on a sag profile produced from the computational methods.
The wellbore fluids used in many wellbore operations include weighting agents (e.g., particles having a density greater than the base fluid including barite, ilmenite, calcium carbonate, marble, and the like) to increase the density of the wellbore fluid. The density of a wellbore fluid effects the hydrostatic pressure in the wellbore, which, when properly matched with the pore pressure of the formation, maintains the formation fluids. If the hydrostatic pressure in the wellbore is too low, the formation fluids may flow uncontrollably to the surface, possibly causing a blowout. If the hydrostatic pressure in the wellbore is too high, the subterranean formation may fracture, which can lead to fluid loss and possibly wellbore collapse.
As used herein, the term “sag” refers to an inhomogeneity or gradation in density of a fluid resulting from particles in the fluid settling (e.g., under the influence of gravity or secondary flow). Sag can be exacerbated with elevated temperatures.
Oftentimes in a wellbore operation, the circulation of the wellbore fluids through the drill string and wellbore is halted such that the wellbore fluid becomes substantially static in the wellbore (e.g., drill string tripping). In some instances, a low shear condition that allows for sag may be encountered when circulation is slowed, when the circulation may be halted and the drill string may be rotating, or a hybrid thereof. As used herein, the term “low shear” refers to a circulation rate of less than about 100 ft/min or a drill string rotation rate of less than 100 rpm. Static or low shear wellbore fluids may allow the weighting agents to settle (i.e., sag). Sag may not occur throughout an entire wellbore, but its occurrence in even a small section of the wellbore can cause well control issues like kicks, lost circulation, stuck pipes, wellbore collapse, and possibly a blowout. For example, if the density of the wellbore fluid, and consequently hydrostatic pressure, are higher than the fracture gradient of the formation, the formation may fracture and cause a lost circulation well control issue. In another example, sag may lead to a portion of the wellbore fluid having a sufficiently high density for a pipe to get stuck therein. Unsticking the pipe can, in some instances, cease the wellbore operation and require expensive and time consuming methods. In yet another example, large density variations in the wellbore fluid from sag can result in wellbore collapse. In another example, in some instances the lower density portion of the sagged fluid may readily flow when circulation is resumed or increased and leave the higher density portion of the fluid in place, which is time consuming and expensive to remove. Each of these well control issues and potential remediation are expensive and time consuming.
Sag in wellbore fluids is exacerbated by higher temperatures and deviation in the wellbore. Therefore, the recent strides in extended reach drilling, which have resulted in highly deviated wellbores at greater depths where temperatures can be greater, increase the concern for and possible instances of sag related problems in the oil and gas industry.